Reduction of a tool wave excited by a transmitter of a well logging tool

ABSTRACT

A logging tool for performing well logging activities in a geologic formation has one or more transmitters, one or more receivers, and a tool wave propagating factor which differs from a formation wave propagating factor. The one or more transmitters excite a tool wave and formation wave. The tool wave is reduced by the one or more transmitters transmitting an acoustic wave which causes the tool wave to be reduced. Additionally, or alternatively, the tool wave is reduced by generating an inverse estimate of the tool wave based on waveform data associated with the tool wave and formation wave received by each of the one or more receivers.

TECHNICAL FIELD

This disclosure relates generally to well logging tools which recordproperties of a geologic formation and more particularly to reduction ofa tool wave excited by a transmitter of the well logging tool.

BACKGROUND ART

Well logging tools record properties of a geologic formation. They havea transmitter for transmitting an acoustic wave into the geologicformation and a receiver for receiving a formation wave from thegeologic formation. The formation wave indicates properties of theformation, including presence of hydrocarbon in the formation andcondition of cement which lines a borehole in the geologic formation.When the acoustic wave is transmitted, a tool wave is excited along thesonic tool, from the transmitter to the receiver. The tool waveinterferes with reception of the formation wave by the receiver.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments of the disclosure may be better understood by referencingthe accompanying drawings.

FIG. 1 illustrates a system for active tool wave reduction.

FIG. 2 illustrates an example tool mandrel of the logging tool forreducing the tool wave via a transmitter approach.

FIG. 3 is a flow chart of functions for reducing the tool wave via thetransmitter approach.

FIG. 4 illustrates slowness of a tool wave propagating factor.

FIG. 5 illustrates attenuation of the tool wave propagating factor.

FIG. 6 illustrates an example tool mandrel of the logging tool forreducing the tool wave via a receiver approach.

FIG. 7 is a flow chart of functions for reducing the tool wave via thereceiver approach.

FIG. 8 illustrates back propagation for reducing the tool wave via thereceiver approach.

FIG. 9 illustrates a comparison between waveform data associated withthe primary transmitter before tool wave reduction and waveform dataassociated with the primary transmitter after tool wave reduction.

FIG. 10 is a schematic diagram of apparatus to perform some of theoperations and functions described with reference to FIGS. 1-9.

FIG. 11 is another schematic diagram of apparatus to perform some of theoperations and functions described with reference to FIGS. 1-9.

FIG. 12 is a block diagram of a computer system associated with reducingthe tool wave via the transmitter and/or receiver approach.

The drawings are for the purpose of illustrating example embodiments,but it is understood that the embodiments are not limited to thearrangements and instrumentality shown in the drawings.

DESCRIPTION OF EMBODIMENTS

The description that follows includes example systems, methods,techniques, and program flows that embody aspects of the disclosure.However, it is understood that this disclosure may be practiced withoutthese specific details. For instance, this disclosure refers to reducinga tool wave excited by a transmitter of a well logging tool positionedin a borehole of a geologic formation in illustrative examples. Aspectsof this disclosure can be applied to reducing other types of wavesexcited by other types of tools in the borehole or other environments.In other instances, well-known instruction instances, protocols,structures and techniques have not been shown in detail in order not toobfuscate the description.

Overview

Tool wave reduction is a process of reducing a tool wave received by areceiver of a well logging tool when a transmitter of the logging tooltransmits an acoustic wave into a geologic formation. Various techniquesexist for reducing the tool wave. One example is to add slotted sleeves,grooved collars, and other attenuation components to the well loggingtool to sonically isolate the transmitter and the receiver to reduce thetool wave that reaches the receiver. The addition of slotted sleeves,grooved collars, and other attenuation components compromise strength ofthe logging tool and a depth range of the logging tool. Another exampleis to apply an array filter to a signal received by the receiver. Thesignal includes the tool wave and a formation wave. The signal isconverted from a space-time domain to a wavenumber frequency domain (F-Kdomain) and filtered by the array filter to reduce the tool wave. Thearray filter outputs the formation wave which is converted back to thespace-time domain. In many cases, however, the array filter will not beable to adequately filter the tool wave from the formation wave ifformation wave slowness is close to tool wave slowness.

Embodiments described herein are directed to actively reducing a toolwave received by a receiver of a well logging tool based on atransmitter of the well logging tool transmitting an acoustic wave intothe geologic formation. The well logging tool (also referred to aslogging tool) has a tool mandrel with one or more transmitters and oneor more receivers. The one or more transmitters may transmit an acousticwave which excites the tool wave and a formation wave. The formationwave may include one or more of compressional waves, shear waves, and/orguided waves propagating along the borehole wall excited by the acousticwave. The tool wave includes one or more waves propagating directlyalong a body of the logging tool (e.g., not propagating in the geologicformation) also excited by the acoustic wave. The tool mandrel has atool wave propagating factor different from a formation wave propagatingfactor to facilitate reducing the tool wave. The tool wave is reducedvia a transmitter approach and/or a receiver approach.

In the transmitter approach, the one or more transmitters each transmitan acoustic wave with phases and/or amplitudes that collectively causethe tool wave received by the one or more receivers to be reduced. Forexample, the primary transmitter may transmit an acoustic wave whichexcites a formation wave in the formation and a tool wave in the toolmandrel. At a same time the primary transmitter transmits the acousticwave, one or more auxiliary transmitters each transmit an acoustic wavewith phases and/or amplitudes that excite an inverse phase to the toolwave in the tool mandrel. The inverse phase to the tool wave reduces thetool wave excited by the primary transmitter and tool wave received bythe one or more receivers.

In the receiver approach, the one or more receivers may receive both theformation wave and tool wave. The tool wave may be separated theformation wave and the formation wave output. A primary receiver of theone or more receivers and one or more auxiliary receivers each receivesthe tool wave and formation wave and converts the received tool wave andformation wave into respective waveform data. The waveform data fromeach of the auxiliary receivers may be used to estimate an inverse phaseof the tool wave in the waveform data associated with the primaryreceiver. The estimate may be generated by back propagating the waveformdata associated with each of the auxiliary receivers based on a positionof the primary receiver. Then, the tool wave in the waveform dataassociated with the primary receiver may be removed based on theestimated inverse phase of the tool wave.

The description that follows includes example systems, apparatuses, andmethods that embody aspects of the disclosure. However, it is understoodthat this disclosure may be practiced without these specific details. Inother instances, well-known instruction instances, structures andtechniques have not been shown in detail in order not to obfuscate thedescription.

Example Illustrations

FIG. 1 illustrates a system 100 for active tool wave reduction. Thesystem 100 includes a well logging tool 102 (also referred to as loggingtool 102) that can be raised and lowered in a borehole 104 drilled in ageologic formation 106 via a conveyance 150 such as a wireline includingbut not limited to a wireline slickline, coiled tubing, piping, downholetractor, or a combination thereof, or logging while drilling (LWD)apparatus conveyed on a bottom hole assembly. The system 100 alsoincludes a computer system 108 located at the surface 152 of thegeologic formation 106 or downhole.

The borehole 104 may be lined with a casing 110 such as steel tubingsurrounded by cement 112 which fills an annulus between the borehole 104and casing 110. The casing 110 serves multiple purposes. The casing 110prevents the borehole 104 from caving in, keeps hydrocarbon carriedwithin the casing 110 from escaping out of the casing 110, and preventsunwanted fluids such as water outside of the casing 110 from enteringinto the casing 110 and contaminating the hydrocarbon carried within thecasing 110.

A tool mandrel 114 of the logging tool 102 has one or more transmitters118 and one or more receivers 116 along a longitudinal z axis 120 of thelogging tool 102. The one or more transmitters 18 may transmit anacoustic wave 122 which excites a formation wave 124 in the geologicformation 106 and/or tool wave 126 in the tool mandrel 114. Theformation wave 124 may include one or more of compressional waves, shearwaves, and/or guided waves propagating along the wall of the borehole104 excited by the acoustic waves 122. The tool wave 126 is a wavepropagating directly along the tool mandrel 114 (e.g., not propagatingin the geologic formation 106) also excited by the acoustic wave 122.The tool mandrel 114 and/or a body of the logging tool 102 may also havestructure to slow down the tool wave 126 with respect the formationwaves 124. The structure 128 may include one or more of cuttings, holes,grooves of the tool mandrel 114 which causes a tool wave propagatingfactor to be different from a formation wave propagating factor, butdoes not substantially compromise strength of the logging tool 102.

The propagating factor defines a slowness and attenuation of a wave. Theslowness indicates a time for a wave to travel a given distance and theattenuation indicates a reduction in amplitude of the wave. Thepropagating factor is written as k=ωs+iα, where s is the slowness of awave, α is the attenuation of the wave, and ω is a frequency of thewave. The tool wave may have a propagating factor k_(tool) and theformation waves may have a propagating factor k_(formation) depending oncharacteristics of the tool mandrel 114 and geologic formation 106,respectively, and each propagating factor may be different.

The computer system 108 may have a transmitter control 130 and receivercontrol 132. The transmitter control 130 may control transmission of theacoustic wave 118 in a sonic frequency range by each of the one or moretransmitters 118. The acoustic wave 118 may have one or more givenfrequencies and/or one or more given amplitudes. Each transmitter 118may be arranged to transmit a same acoustic wave. Alternatively, onetransmitter 118 may transmit an acoustic wave which differs (inamplitude and/or frequency) from another acoustic wave transmitted byanother transmitter 118. Each transmitter 118 may be also arranged totransmit the acoustic wave at a same time as another transmitter 118 orat different times. The receiver control 132 may control reception ofthe formation wave 124 and/or tool wave 126 resulting from thetransmission of the acoustic wave 12. One receiver 116 may be arrangedto receive the formation wave 124 and/or tool wave 126 at a same time asanother receiver 116 or at a different time.

The computer system 108 may also have an active tool wave reductionsystem 134. The active tool wave reduction system 134 may reduce thetool wave 126 received by the one or more receivers 116. The activereduction may be based on a transmitter approach and/or receiverapproach. For example, in the transmitter approach, the transmittercontrol may cause the two or more transmitters to each transmit anacoustic wave with phases and/or amplitudes that cause the tool wavereceived by the one or more receivers to be reduced. As another example,in the receiver approach, the two or more receivers may receive both theformation wave and tool wave. The tool wave may be separated theformation wave and the formation wave output.

The formation wave may be used to determine a formation slowness logand/or a wave amplitude log. The formation slowness log indicatesslowness of the formation waves as a function of depth in the geologicformation 106. The slowness indicates formation properties in thegeologic formation 106 which can be used to determine a drillingdirection for extraction of hydrocarbon from the geologic formation 106.The formation slowness log may be used in other ways as well. The waveamplitude log may indicate conditions in the borehole 104 such as anintegrity of the cement 110 between the casing 112 and borehole 104 as afunction of depth.

FIG. 2 illustrates an example tool mandrel 200 for reducing the toolwave via a transmitter approach. The tool mandrel 200 has a primarytransmitter 202 and one or more auxiliary transmitters 204 positionedalong the longitudinal z axis of the tool mandrel 200. The tool mandrel200 may also have a receiver 206. In one or more examples, the primarytransmitter 202 and one or more auxiliary transmitters 204 may be nodifferent, other than its position along the mandrel 200. In one or moreexamples, the receiver 206 may be located further downhole from theprimary transmitter 202 and the one or more auxiliary transmitters 204when the tool mandrel 200 is positioned in a borehole. The tool mandrel200 may be designed and/or modified with structure 208 (e.g., cuttings,holes, grooves) to ensure that the tool wave propagating factor (e.g.,slowness and/or attenuation) is different from the formation wavepropagating factor. For example, the tool mandrel 200 may have aslowness or attenuation that the general rock formation does not have.The primary transmitter 202 and one or more auxiliary transmitters 204may transmit an acoustic wave such that the tool wave is reduced at theone or more receivers 206.

FIG. 3 is a flow chart of functions 300 for reducing the tool wave viathe transmitter approach. At 302, the primary transmitter may transmitan acoustic wave which excites a formation wave in the formation and atool wave in the tool mandrel. The primary transmitter may be drivenwith a drive signal which causes the primary transmitter to output theacoustic wave. The drive signal may be represented as f_(Pri)(ω) whichis function of frequency ω in the frequency domain. At 304, one or moreauxiliary transmitters transmit, at a same time the primary transmittertransmits the acoustic wave, a respective acoustic wave which excites atool wave with an inverse phase (e.g., same absolute amplitude andopposite phase, also referred to as inverse) to the tool wave excited bythe primary transmitter, causing the tool wave excited by the primarytransmitter to be reduced. Each transmitter n may be driven with a drivesignal represented by the following equation:

f _(Aux) ^(n)(ω)=−f _(Pri)(ω)exp(ik _(tool)(z _(Aux) ^(n) −z_(Pri)))  (1)

where f_(Pri)(ω) is the drive pulse in the frequency domain at theprimary transmitter, k_(tool) represents the tool wave propagatingfactor (e.g., k_(tool)=ωs_(tool)+iα), and z_(Pri) and z_(Aux) ^(n)denote the z axis position of the primary transmitter and the auxiliarytransmitter respectively along the tool mandrel of the logging tool.Each transmitter n is driven with a corresponding drive signal. Thedrive signal which drives a given transmitter causes the giventransmitter to generate a corresponding acoustic wave. In one or moreexamples, the drive signal may have a similar amplitude and/or phasecharacteristics as the corresponding acoustic wave which is generated.

The tool wave propagating factor may be determined in many ways. In oneexample, slowness and attenuation associated with the tool wavepropagating factor may be determined based on design of the toolmandrel. The materials and/or shape of the tool mandrel may determinethe tool wave propagating factor. In another example, the tool wavepropagating factor may be determined based on analysis of the wavesreceived by the one or more receivers.

FIG. 4 illustrates example waves 400 received by the one or morereceivers R1 to R6 as a function of a time index 402. The example waves400 may be used to determine the slowness of the tool wave propagatingfactor by analysis. The primary receiver R1 may be located closest tothe transmitter and receive a wave before the receivers R2 to R6 receivethe wave. The wave received by the primary receiver is labeled as R1 anda wave received by each of the auxiliary receivers is labeled as R2 toR6, respectively. The rectangular box 402 indicates the tool wave whoseslowness is 67 s/ft.

FIG. 5 illustrates determining an attenuation of the tool wave based onthe example waves 400. Each receiver may receive a tool wave. The toolwave received by each receiver may be normalized and plotted as afunction of amplitude on a vertical axis 502 and the receiver whichreceived the tool wave on a horizontal axis 504 (indicated as a receiverindex). The plotted normalized tool wave amplitude 500 is shown ascircles 506 associated with each receiver. An attenuation of the toolwave is calculated based on the normalized tool wave amplitudes. Thenormalized tool wave amplitudes are fit to a line 508 indicative of theattenuation. With a linear fit on the amplitude in dB, the attenuationof the tool wave is calculated to be 3.5 dB/ft.

Equation (1) intuitively calculates what drive signal causes theauxiliary transmitters excite an inverse-phase tool wave at the positionof the primary transmitter and/or further downhole which will thenpropagate to the receiver. In one or more examples, the excitedinverse-phase tool wave may have an opposite phase (e.g., 180 degreeshift) and/or same absolute amplitude to the tool wave excited by theprimary transmitter at the position of the primary transmitter and/orfurther downhole. Further, different weights may be applied to eachdrive signal associated with each auxiliary transmitter to differcontribution of each auxiliary transmitter. As a result of thetransmission by the primary and auxiliary transmitters, the tool wave isreduced at the receiver. The reduction is analytically calculated as:

$\begin{matrix}{\min\left\{ {{\sum\limits_{n = 1}^{N}\;{{{Weight}(n)}{f_{Aux}^{n}(\omega)}{\exp\left( {{ik}_{tool}\left( {z_{Pri} - z_{Aux}^{n}} \right)} \right)}}} + {f_{Pri}(\omega)}} \right\}} & (2)\end{matrix}$

where Weight(n) represents amplitude weights applied at differentauxiliary transmitters n. For example, Weight(n)=1/N may indicateunified weights. As another example, weights may be calculated based ona signal to noise ratio (SNR) values of an expected tool wave at a giventransmitter, in order to improve reduction of the tool wave and increaseSNR of the resulting formation wave received at a receiver.

FIG. 6 illustrates an example of the tool mandrel 600 for reducing thetool wave via the receiver approach. The tool mandrel 600 has atransmitter 602, a primary receiver 604, and one or more auxiliaryreceivers 606, each positioned along a longitudinal axis z of the toolmandrel 600. In one or more examples, the primary receiver 604 and oneor more auxiliary receivers 606 may be located further downhole from thetransmitter 602 when the tool mandrel 600 is positioned in a borehole.The primary receiver may be in between other auxiliary receivers in theexample shown in FIG. 6. In other examples, a first receiver may be aprimary receiver and further receivers downhole from the transmitter andprimary receiver may be auxiliary receivers. In one or more examples,the primary receiver 604 and one or more auxiliary receivers 606 may beno different, other than its position along the mandrel 600. The toolmandrel 600 may be designed and/or modified with structure 608 (e.g.,cuttings, holes, grooves) so that the tool wave propagating factor(e.g., slowness and/or attenuation) is different from the formation wavepropagating factor. For example, the tool mandrel 600 may have aslowness or attenuation that the general rock formation does not have.The primary receiver 604 and one or more auxiliary receivers 606 mayeach receive a tool wave and formation wave.

FIG. 7 is a flow chart of functions 700 for reducing the tool wave viathe receiver approach. At 702, a transmitter may transmit an acousticwave which excites a formation wave in the geologic formation and a toolwave in the tool mandrel. At 704, a primary receiver and the one or moreauxiliary receivers each receives the tool wave and formation wave andconverts the received waves into respective waveform data indicative ofthe received waves. At 706, a tool wave in the waveform data associatedwith the primary receiver may be reduced based on the respectivewaveform data associated with the one or more auxiliary receivers. Forexample, the waveform data from each of the auxiliary receivers may beused to estimate an inverse phase of the tool wave in the waveform dataassociated with the primary receiver.

The estimated tool wave may be created by backpropagating the waveformdata associated with each of the auxiliary receivers based on a positionof the primary receiver and auxiliary receiver:

$\begin{matrix}{{{{Wav}_{RTool}(\omega)} = {- {\sum\limits_{n = 1}^{N}\;{{{Weight}(n)}{{Wav}_{Aux}^{n}(\omega)}{\exp\left( {{ik}_{tool}\left( {z_{Pri} - z_{Aux}^{n}} \right)} \right)}}}}},} & (3)\end{matrix}$

where Wav_(RTool) represents the estimated tool wave, Wav_(Aux) ^(n)(ω)represent waveform data at the nth auxiliary receiver, Weight(n)represent weights to differ contribution of each the waveform associatedwith each auxiliary receiver, and z_(Pri) and z_(Aux) ^(n) denote the zaxis position of the primary receiver and the auxiliary receiverrespectively along the tool mandrel of the logging tool. To simplify theprocessing, equation 3 might be implemented in the time-domain as:

$\begin{matrix}{{{{{Wav}^{\prime}}_{RTool}(t)} = {- {\sum\limits_{n = 1}^{N}\;{{{Weight}(n)}{{{Wav}^{\prime}}_{Aux}^{n}\left( {t - {s_{tool}\left( {z_{Pri} - z_{Aux}^{n}} \right)}} \right)}{\exp\left( {{i\alpha}_{tool}\left( {z_{Pri} - z_{Aux}^{n}} \right)} \right)}}}}},} & (4)\end{matrix}$

where s_(tool) represents tool wave slowness, α_(tool) represents toolwave attenuation.

FIG. 8 illustrates a back propagation process 800 associated with toolwave reduction via the receiver approach. Waveforms are plotted as afunction of amplitude 802 and time index 804. Primary waveform 806represents waveform data received by the primary receiver. R2 to R6represent waveform data received by auxiliary receivers R2 to R6 afterback propagation where the weight of each waveform is selected as 0.2.Estimated waveform data predicted by equation 4 and shown asreconstructed waveform 808 has equal absolute amplitude and oppositephase compared to the primary waveform 806 (e.g., inverse phase to thetool wave). The tool wave may be removed from the primary waveform byfurther signal processing:

Wav _(For)(ω)=Wav _(Pri)(ω)+Wav _(RTool)(ω),  (5)

or in the time domain, by

Wav′ _(For)(t)=Wav′ _(Pri)(t)+Wav′ _(RTool)(t),  (6)

where Wav_(For)(ω) and Wav′_(For)(t) represent remaining target signals(e.g., formation wave) in the frequency domain and in the time domain,respectively.

FIG. 9 illustrates a comparison 900 between the waveform data 902associated with the primary receiver before tool wave reduction and thewaveform data 904 associated with the primary receiver after tool wavereduction plotted as a function of amplitude 906 and time index 908. Thetool wave is suppressed by about −20 dB.

Other variations for actively reducing the tool wave are also possible.In one example, each transmitter of the tool mandrel 200 may transmit anacoustic wave to the receiver in sequence to the receiver such that eachtransmission by each transmitter does not overlap. Equations 3-4 may beapplied to each wavedata received by each receiver based on transmissionof the acoustic wave by each transmitter in sequence to estimate aninverse phase of a tool wave. In this regard, Wav_(Aux) ^(n)(ω)represents waveform data associated with waves received by the receiverbased on transmission by the nth auxiliary transmittter. The primarytransmitter transmitting an acoustic wave to the receiver may excite atool wave which is then removed using the estimated inverse phase toolwave based on equations 5-6. In another example, both the transmitterand receiver approach may be combined to perform tool wave reduction.The transmitter approach may reduce the tool wave and the receiverapproach may also reduce any tool wave not reduced by the transmitterapproach. In yet another example, multiple receivers may be consideredcollectively as the primary receiver while remaining receivers areauxiliary receivers. With l representing each of the primary receivers,the tool wave is reduced via the following signal processing on wavedataassociated with each receiver similar to equations 3-6 above:

${{{Wav}_{RTool}^{l}(\omega)} = {- {\sum\limits_{n = 1}^{N}\;{{{Weight}(n)}{{Wav}_{Aux}^{n}(\omega)}{\exp\left( {{ik}_{tool}\left( {z_{Pri}^{l} - z_{Aux}^{n}} \right)} \right)}}}}},{{{Wav}_{RTool}^{l}(t)} = {- {\sum\limits_{n = 1}^{N}\;{{{Weight}(n)}{{{Wav}^{\prime}}_{Aux}^{n}\left( {t - {s_{tool}\left( {z_{Pri}^{l} - z_{Aux}^{n}} \right)}} \right)}{\exp\left( {{i\alpha}_{tool}\left( {z_{Pri}^{l} - z_{Aux}^{n}} \right)} \right)}}}}},{{{Wav}_{For}^{l}(\omega)} = {{{Wav}_{Pri}^{l}(\omega)} + {{Wav}_{RTool}^{l}(\omega)}}},{{{Wav}_{For}^{l}(t)} = {{{Wav}_{Pri}^{l}(t)} + {{Wav}_{RTool}^{l}(t)}}}$

FIG. 10 is a schematic diagram of an apparatus 1000 that can be used toperform some of the operations and functions described with reference toFIGS. 1-9. A schematic diagram 1000 is shown of downhole tool 102 on awireline 1050. As illustrated, a borehole 104 may extend through thegeologic formation 1002. It should be noted that while FIG. 10 generallydepicts a land-based wireline logging system, those skilled in the artwill readily recognize that the principles described herein are equallyapplicable to subsea logging operations that employ floating orsea-based platforms and rigs, without departing from the scope of thedisclosure.

As illustrated, hoist 1004 may be used to run a logging tool 102 intoborehole 104. Hoist 1004 may be disposed on a recovery vehicle 1006.Hoist 1004 may be used, for example, to raise and lower wireline 1050 inborehole 104. While hoist 1004 is shown on recovery vehicle 1006, itshould be understood that wireline 1050 may alternatively be disposedfrom a hoist 1004 that is installed at the surface 1008 instead of beinglocated on recovery vehicle 1006. Logging tool 102 may be suspended inborehole 104 on wireline 1050. Other conveyance types may be used forconveying logging tool 102 into borehole 104, including coiled tubing,wired drill pipe, slickline, and downhole tractor, for example. Loggingtool 102 may comprise a tool mandrel, which may be elongated as shown onFIG. 10. Tool body may be any suitable material, including withoutlimitation titanium, stainless steel, alloys, plastic, combinationsthereof, and the like. Logging tool 102 may further include one or moretransmitters and one or more receivers for tool wave reduction.

Computer system 1032 may include a processing unit 1036, a monitor 1038,an input device 1040 (e.g., keyboard, mouse, etc.), and/ormachine-readable media 1042 (e.g., optical disks, magnetic disks) thatcan store code representative of the methods described herein forreducing the tool wave excited by a transmitter of the logging tool 102via the transmitter and/or receiver approach. To facilitate tool wavereduction, communication link 1034 (which may be wired or wireless, forexample) may transmit waveform data associated with one or morereceivers from the logging tool 102 and the computer system 1032 atsurface 1008 and/or drive signals from the computer system 1132 to thelogging tool 102 to cause the one or more transmitters to output anacoustic wave to reduce the tool wave. Communication link 1034 mayimplement one or more of various known telemetry techniques such asmud-pulse, acoustic, electromagnetic, etc. In addition to, or in placeof processing at the surface 1008, processing for reducing the tool wavemay occur downhole by the logging tool 102.

FIG. 11 is another schematic diagram of an apparatus 1100 that can beused to perform some of the operations and functions described withreference to FIGS. 1-9. The apparatus 1100 includes a logging tool 102disposed on a drill string 1102 of a depicted well apparatus 1100. Asillustrated, a borehole 104 may extend through geologic formation 1104.While borehole 104 is shown extending generally vertically into thegeological formation 1104, the principles described herein are alsoapplicable to boreholes that extend at an angle through the geologicalformation 1104, such as horizontal and slanted boreholes. For example,although FIG. 11 shows a vertical or low inclination angle well, highinclination angle or horizontal placement of the well and equipment isalso possible. It should further be noted that while FIG. 11 generallydepicts a land-based operation, those skilled in the art will readilyrecognize that the principles described herein are equally applicable tosubsea operations that employ floating or sea-based platforms and rigs,without departing from the scope of the disclosure.

The apparatus further includes a drilling platform 1106 that supports aderrick 1108 having a traveling block 1110 for raising and loweringdrill string 1102. Drill string 1102 may include, but is not limited to,drill pipe and coiled tubing, as generally known to those skilled in theart. A kelly 1112 may support drill string 1102 as it may be loweredthrough a rotary table 1114. A drill bit 1120 may be attached to thedistal end of drill string 1102 and may be driven either by a downholemotor and/or via rotation of drill string 1102 from the surface 1118.Without limitation, drill bit 1120 may include, roller cone bits, PDCbits, natural diamond bits, any hole openers, reamers, coring bits, andthe like. As drill bit 1120 rotates, it may create and extend borehole104 that penetrates various subterranean formations such as 1104. A pump1122 may circulate drilling fluid through a feed pipe 1124 to kelly1112, downhole through interior of drill string 1102, through orificesin drill bit 1120, back to surface 1118 via annulus 1122 surroundingdrill string 1102, and into a retention pit 1126.

Drill bit 1120 may be just one piece of a downhole assembly that mayinclude the logging tool 102. Logging tool 102 may be made of anysuitable material, including without limitation titanium, stainlesssteel, alloys, plastic, combinations thereof, and the like. Logging tool102 may further include one or more transmitters 1130 and one or morereceivers 1131 for actively reducing a tool wave excited by the loggingtool 102 separated by a collar 1128.

Computer system 1132 may include a processing unit 1136, a monitor 1138,an input device 1140 (e.g., keyboard, mouse, etc.), and/or machinereadable media 1142 (e.g., optical disks, magnetic disks) that can storecode representative of the methods described herein for reducing thetool wave excited by a transmitter 1130 of the logging tool 102 via thetransmitter and/or receiver approach. Computer system 1132 may act as adata acquisition system and data processing system to reduce the toolwave. This processing may occur at the surface 1118 in real-time.Alternatively, the processing may occur at surface 1118 or anotherlocation after withdrawal of logging tool 102 from borehole 104. Stillalternatively, the processing may be performed downhole in the geologicformation 1104 by the logging tool 102. Any suitable technique may beused for transmitting signals, e.g., waveform data, to the computersystem 1132 residing on the surface 1118. As illustrated, acommunication link 1134 (which may be wired or wireless, for example)may transmit data between the logging tool 102 and the computer system1132 at the surface 1118. The data may be waveform data associated withthe one or more receivers 1131 transmitted from the logging tool 102 tothe computer system 1132 and/or drive signals transmitted from thecomputer system 1132 to the logging tool 102 to cause the one or moretransmitters to output an acoustic wave to reduce the tool wave.

FIG. 12 is a block diagram 1200 of apparatus of the computer system1032, 1132 and/or the logging tool 102 for actively reducing a toolwave. The apparatus may be located on the surface, downhole, orpartially on the surface and partially downhole.

The block diagram 1200 includes a processor 1202 (possibly includingmultiple processors, multiple cores, multiple nodes, and/or implementingmulti-threading, etc.). The block diagram 1200 includes memory 1204. Thememory 1204 may be system memory (e.g., one or more of cache, SRAM,DRAM, zero capacitor RAM, Twin Transistor RAM, eDRAM, EDO RAM, DDR RAM,EEPROM, NRAM, RRAM, SONOS, PRAM, etc.) or any one or more other possiblerealizations of non-transitory machine-readable media/medium.

The block diagram 1200 may also include a persistent data storage 1206.The persistent data storage 1206 can be a hard disk drive, such as amagnetic storage device which stores one or more of waveform data. Theblock diagram 1200 also includes a bus 1208 (e.g., PCI, ISA,PCI-Express) and a network interface 1210 in communication with alogging tool. The block diagram 1200 may also have an active tool wavereduction system 1214, a transmitter control 1216, and receiver control1218 to actively reduce a tool wave in accordance with the methodsdescribed herein, including the described transmitter approach andreceiver approach.

The block diagram 1200 may further comprise a user interface 1212 in thecase when the block diagram 1200 is associated with the computer system1032, 1132. The user interface 1212 may include a display such as acomputer screen or other visual device to show the formation waves toengineering personnel. The user interface 1214 may also include an inputdevice such as a mouse, keyboard.

The block diagram 1200 may implement any one of the previously describedtool wave reduction functionalities partially (or entirely) in hardwareand/or software (e.g., computer code, program instructions, programcode) stored on a non-transitory machine readable medium/media. In someinstances, the software is executed by the processor 1202. Further,realizations can include fewer or additional components not illustratedin FIG. 12 (e.g., video cards, audio cards, additional networkinterfaces, peripheral devices, etc.). The processor 1202 and the memory1204 are coupled to the bus 1208. Although illustrated as being coupledto the bus 1208, the memory 1204 can be coupled to the processor 1202.

The flowcharts are provided to aid in understanding the illustrationsand are not to be used to limit scope of the claims. The flowchartsdepict example operations that can vary within the scope of the claims.Additional operations may be performed; fewer operations may beperformed; the operations may be performed in parallel; and theoperations may be performed in a different order. For example, theoperations depicted in blocks 302, 304 and 702 to 706 can be performedin parallel or concurrently. It will be understood that each block ofthe flowchart illustrations and/or block diagrams, and combinations ofblocks in the flowchart illustrations and/or block diagrams, can beimplemented by program code. The program code may be provided to aprocessor of a general purpose computer, special purpose computer, orother programmable machine or apparatus.

As will be appreciated, aspects of the disclosure may be embodied as asystem, method or program code/instructions stored in one or moremachine-readable media. Accordingly, aspects may take the form ofhardware, software (including firmware, resident software, micro-code,etc.), or a combination of software and hardware aspects that may allgenerally be referred to herein as a “circuit,” “module” or “system.”The functionality presented as individual modules/units in the exampleillustrations can be organized differently in accordance with any one ofplatform (operating system and/or hardware), application ecosystem,interfaces, programmer preferences, programming language, administratorpreferences, etc.

Any combination of one or more machine readable medium(s) may beutilized. The machine readable medium may be a machine readable signalmedium or a machine readable storage medium. A machine readable storagemedium may be, for example, but not limited to, a system, apparatus, ordevice, that employs any one of or combination of electronic, magnetic,optical, electromagnetic, infrared, or semiconductor technology to storeprogram code. More specific examples (a non-exhaustive list) of themachine readable storage medium would include the following: a portablecomputer diskette, a hard disk, a random access memory (RAM), aread-only memory (ROM), an erasable programmable read-only memory (EPROMor Flash memory), a portable compact disc read-only memory (CD-ROM), anoptical storage device, a magnetic storage device, or any suitablecombination of the foregoing. In the context of this document, a machinereadable storage medium may be any tangible medium that can contain, orstore a program for use by or in connection with an instructionexecution system, apparatus, or device. A machine readable storagemedium is not a machine readable signal medium.

A machine readable signal medium may include a propagated data signalwith machine readable program code embodied therein, for example, inbaseband or as part of a carrier wave. Such a propagated signal may takeany of a variety of forms, including, but not limited to,electro-magnetic, optical, or any suitable combination thereof. Amachine readable signal medium may be any machine readable medium thatis not a machine readable storage medium and that can communicate,propagate, or transport a program for use by or in connection with aninstruction execution system, apparatus, or device.

Program code embodied on a machine readable medium may be transmittedusing any appropriate medium, including but not limited to wireless,wireline, optical fiber cable, RF, etc., or any suitable combination ofthe foregoing.

Computer program code for carrying out operations for aspects of thedisclosure may be written in any combination of one or more programminglanguages, including an object oriented programming language such as theJava® programming language, C++ or the like; a dynamic programminglanguage such as Python; a scripting language such as Perl programminglanguage or PowerShell script language; and conventional proceduralprogramming languages, such as the “C” programming language or similarprogramming languages. The program code may execute entirely on astand-alone machine, may execute in a distributed manner across multiplemachines, and may execute on one machine while providing results and oraccepting input on another machine.

The program code/instructions may also be stored in a machine readablemedium that can direct a machine to function in a particular manner,such that the instructions stored in the machine readable medium producean article of manufacture including instructions which implement thefunction/act specified in the flowchart and/or block diagram block orblocks.

While the aspects of the disclosure are described with reference tovarious implementations and exploitations, it will be understood thatthese aspects are illustrative and that the scope of the claims is notlimited to them. In general, techniques for reducing a tool wave excitedby a logging tool as described herein may be implemented with facilitiesconsistent with any hardware system or hardware systems. Manyvariations, modifications, additions, and improvements are possible.

Plural instances may be provided for components, operations orstructures described herein as a single instance. Finally, boundariesbetween various components, operations and data stores are somewhatarbitrary, and particular operations are illustrated in the context ofspecific illustrative configurations. Other allocations of functionalityare envisioned and may fall within the scope of the disclosure. Ingeneral, structures and functionality presented as separate componentsin the example configurations may be implemented as a combined structureor component. Similarly, structures and functionality presented as asingle component may be implemented as separate components. These andother variations, modifications, additions, and improvements may fallwithin the scope of the disclosure.

Use of the phrase “at least one of” preceding a list with theconjunction “and” should not be treated as an exclusive list and shouldnot be construed as a list of categories with one item from eachcategory, unless specifically stated otherwise. A clause that recites“at least one of A, B. and C” can be infringed with only one of thelisted items, multiple of the listed items, and one or more of the itemsin the list and another item not listed.

As used herein, the term “or” is inclusive unless otherwise explicitlynoted. Thus, the phrase “at least one of A, B. or C” is satisfied by anyelement from the set {A, B, C} or any combination thereof, includingmultiples of any element.

Example Embodiments

Example embodiments include the following:

Embodiment 1: A method comprising: transmitting, by a primarytransmitter positioned along a longitudinal axis of a logging tool, anacoustic wave into a geologic formation which excites a tool wave in thelogging tool and a formation wave in the geologic formation, wherein thelogging tool comprises a tool wave propagating factor which is differentfrom a formation wave propagating factor; transmitting, by one or moreauxiliary transmitters positioned along the longitudinal axis of thelogging tool, an acoustic wave which causes the tool wave excited by theprimary transmitter to be reduced; receiving, by one or more receiversalong the longitudinal axis of the logging tool, the formation wave andthe reduced tool wave.

Embodiment 2: The method of Embodiment 1, wherein transmitting, by oneor more auxiliary transmitters of the logging tool, the acoustic wavecomprises driving a given auxiliary transmitter with a drive signalapplied to the primary transmitter, adjusted by the tool wavepropagating factor.

Embodiment 3: The method of Embodiment 1 or 2, wherein the tool wavepropagating factor indicates a slowness and attenuation of the toolwave.

Embodiment 4: The method of any one of Embodiment 1-3, wherein the drivesignal is further adjusted based on a distance between the primarytransmitter and the given auxiliary transmitter.

Embodiment 5: The method of any one of Embodiment 1-4, wherein theprimary transmitter and the one or more auxiliary transmitters transmita respective acoustic wave at a same time.

Embodiment 6: The method of any one of Embodiment 1-5, wherein theacoustic wave which causes the tool wave excited by the primarytransmitter to be reduced, excites an inverse of the tool wave in thelogging tool.

Embodiment 7: The method of any one of Embodiment 1-6, whereintransmitting, by one or more auxiliary transmitters of the logging tool,the acoustic wave which causes the tool wave excited by the primarytransmitter to be reduced comprises transmitting by each of the one ormore auxiliary transmitters a respective acoustic wave based on one ormore weights.

Embodiment 8: A system comprising: a logging tool comprising one or moretransmitters and one or more receivers, wherein the one or moretransmitters and one or more receivers are positioned along alongitudinal axis of the logging tool, and wherein the logging toolcomprises a tool wave propagating factor which is different from aformation wave propagating factor; a processor; a non-transitory machinereadable media having program code executable by the processor to causethe processor to: transmit, by a primary transmitter of the one or moretransmitters of the logging tool, an acoustic wave into a geologicformation which excites a tool wave in the logging tool and a formationwave in the geologic formation; transmit, by one or more auxiliarytransmitters of the one or more receivers of the logging tool, anacoustic wave which causes the tool wave excited by the primarytransmitter to be reduced; receive, by one or more receivers of thelogging tool, the formation wave and the reduced tool wave.

Embodiment 9: The system of Embodiment 8, wherein the program code totransmit, by one or more auxiliary transmitters of the logging tool, theacoustic wave comprises program code to drive a given auxiliarytransmitter with a drive signal applied to the primary transmitter,adjusted by the tool wave propagating factor.

Embodiment 10: The system of Embodiment 8 or 9, wherein the tool wavepropagating factor indicates a slowness and attenuation of the toolwave.

Embodiment 11: The system of any one of Embodiment 8-10, wherein thedrive signal is further adjusted based on a distance between the primarytransmitter and the given auxiliary transmitter.

Embodiment 12: The system of any one of Embodiment 8-11, wherein theprimary transmitter and the one or more auxiliary transmitters transmita respective acoustic wave at a same time.

Embodiment 13: The system of any one of Embodiment 8-12, wherein theacoustic wave which causes the tool wave excited by the primarytransmitter to be reduced, excites an inverse of the tool wave.

Embodiment 14: The system of any one of Embodiment 8-13, wherein theprogram code to transmit, by one or more auxiliary transmitters of thelogging tool, the acoustic wave which causes the tool wave excited bythe primary transmitter to be reduced comprises program code to transmitby each of the one or more auxiliary transmitters a respective acousticwave based on one or more weights.

Embodiment 15: A method comprising: transmitting, by a transmitterpositioned along a longitudinal axis of a logging tool, an acoustic waveinto a geologic formation which excites a tool wave and a formation wavein the geologic formation, wherein the logging tool comprises a toolwave propagating factor which is different from a formation wavepropagating factor; receiving, by one or more receivers positioned alongthe longitudinal axis of the logging tool, the formation wave and thetool wave; propagating waveform data associated with the tool wave andformation wave received by an auxiliary receiver of the one or morereceivers based on a distance between the auxiliary receiver and aprimary receiver of the one or more receivers; and reducing the toolwave in waveform data associated with the formation wave and the toolwave received by a primary receiver of the one or more receivers basedon the propagated waveform data.

Embodiment 16: The method of Embodiment 15, wherein the tool wavepropagating factor indicates a slowness and attenuation of the toolwave.

Embodiment 17: The method of Embodiment 15 or 16, wherein the propagatedwaveform data associated with each receiver represents an inverse of thetool wave.

Embodiment 18: The method of any one of Embodiment 15-17, furthercomprising weighting an amplitude of the propagated waveform dataassociated with a given receiver of the one or more receivers.

Embodiment 19: The method of any one of Embodiment 15-18, whereinpropagating the waveform data comprises forward or back propagating thewaveform data based on a spatial position of the auxiliary receiver withrespect to the primary receiver.

Embodiment 20: The method of any one of Embodiment 15-19, whereinpropagating the waveform data comprises adjusting the waveform data bythe tool wave propagating factor.

What is claimed is:
 1. A method comprising: transmitting, by a primary transmitter positioned along a longitudinal axis of a logging tool, an acoustic wave into a geologic formation which excites a tool wave in the logging tool and a formation wave in the geologic formation, wherein the logging tool comprises a tool wave propagating factor which is different from a formation wave propagating factor; transmitting, by one or more auxiliary transmitters positioned along the longitudinal axis of the logging tool, an acoustic wave which causes the tool wave excited by the primary transmitter to be reduced; receiving, by one or more receivers along the longitudinal axis of the logging tool, the formation wave and the reduced tool wave.
 2. The method of claim 1, wherein transmitting, by one or more auxiliary transmitters of the logging tool, the acoustic wave comprises driving a given auxiliary transmitter with a drive signal applied to the primary transmitter, adjusted by the tool wave propagating factor.
 3. The method of claim 2, wherein the tool wave propagating factor indicates a slowness and attenuation of the tool wave.
 4. The method of claim 2, wherein the drive signal is further adjusted based on a distance between the primary transmitter and the given auxiliary transmitter.
 5. The method of claim 1, wherein the primary transmitter and the one or more auxiliary transmitters transmit a respective acoustic wave at a same time.
 6. The method of claim 1, wherein the acoustic wave which causes the tool wave excited by the primary transmitter to be reduced, excites an inverse of the tool wave in the logging tool.
 7. The method of claim 1, wherein transmitting, by one or more auxiliary transmitters of the logging tool, the acoustic wave which causes the tool wave excited by the primary transmitter to be reduced comprises transmitting by each of the one or more auxiliary transmitters a respective acoustic wave based on one or more weights.
 8. A system comprising: a logging tool comprising one or more transmitters and one or more receivers, wherein the one or more transmitters and one or more receivers are positioned along a longitudinal axis of the logging tool, and wherein the logging tool comprises a tool wave propagating factor which is different from a formation wave propagating factor; a processor; a non-transitory machine readable media having program code executable by the processor to cause the processor to: transmit, by a primary transmitter of the one or more transmitters of the logging tool, an acoustic wave into a geologic formation which excites a tool wave in the logging tool and a formation wave in the geologic formation; transmit, by one or more auxiliary transmitters of the one or more receivers of the logging tool, an acoustic wave which causes the tool wave excited by the primary transmitter to be reduced; receive, by one or more receivers of the logging tool, the formation wave and the reduced tool wave.
 9. The system of claim 1, wherein the program code to transmit, by one or more auxiliary transmitters of the logging tool, the acoustic wave comprises program code to drive a given auxiliary transmitter with a drive signal applied to the primary transmitter, adjusted by the tool wave propagating factor.
 10. The system of claim 9, wherein the tool wave propagating factor indicates a slowness and attenuation of the tool wave.
 11. The system of claim 9, wherein the drive signal is further adjusted based on a distance between the primary transmitter and the given auxiliary transmitter.
 12. The system of claim 8, wherein the primary transmitter and the one or more auxiliary transmitters transmit a respective acoustic wave at a same time.
 13. The system of claim 8, wherein the acoustic wave which causes the tool wave excited by the primary transmitter to be reduced, excites an inverse of the tool wave.
 14. The system of claim 8, wherein the program code to transmit, by one or more auxiliary transmitters of the logging tool, the acoustic wave which causes the tool wave excited by the primary transmitter to be reduced comprises program code to transmit by each of the one or more auxiliary transmitters a respective acoustic wave based on one or more weights.
 15. A method comprising: transmitting, by a transmitter positioned along a longitudinal axis of a logging tool, an acoustic wave into a geologic formation which excites a tool wave and a formation wave in the geologic formation, wherein the logging tool comprises a tool wave propagating factor which is different from a formation wave propagating factor; receiving, by one or more receivers positioned along the longitudinal axis of the logging tool, the formation wave and the tool wave; propagating waveform data associated with the tool wave and formation wave received by an auxiliary receiver of the one or more receivers based on a distance between the auxiliary receiver and a primary receiver of the one or more receivers; and reducing the tool wave in waveform data associated with the formation wave and the tool wave received by a primary receiver of the one or more receivers based on the propagated waveform data.
 16. The method of claim 15, wherein the tool wave propagating factor indicates a slowness and attenuation of the tool wave.
 17. The method of claim 15, wherein the propagated waveform data associated with each receiver represents an inverse of the tool wave.
 18. The method of claim 15, further comprising weighting an amplitude of the propagated waveform data associated with a given receiver of the one or more receivers.
 19. The method of claim 15, wherein propagating the waveform data comprises forward or back propagating the waveform data based on a spatial position of the auxiliary receiver with respect to the primary receiver.
 20. The method of claim 15, wherein propagating the waveform data comprises adjusting the waveform data by the tool wave propagating factor. 